Page 1007 – RTO Insider

December 8, 2020

PJM Operating Committee Briefs: Dec. 3, 2020

PJM stakeholders unanimously endorsed new rules related to public distribution microgrids at last week’s Operating Committee meeting.

Natalie Tacka, an engineer in PJM’s applied innovation department, reviewed the proposed changes to Manual 14D: Generator Operational Requirements. Tacka said work on the issue first began last year in the former Distributed Energy Resources Subcommittee (DERS) and continued into the new DER and Inverter-Based Resources Subcommittee (DIRS).

A microgrid is defined as a system of generating facilities and load that can operate both while connected to and off the main grid, Tacka said. PJM is looking to define a public distribution microgrid as one that contains a PJM generating facility that can generate while connected to and “islanded” from the broader grid and uses public utility distribution wires.

Tacka said a public distribution microgrid would not include any NERC bulk electric or transmission facilities. The electric distribution company would determine if the microgrid is wholesale or retail when islanded.

The Manual 14D changes feature new definitions, including one for a microgrid and a public distribution microgrid, along with provisions for operations in island mode like telemetry and notification requirements and outage reporting.

Tacka said minor updates were made to the manual language after a first read held at last month’s OC meeting.

PJM Operating Committee — PJM’s public distribution microgrid concept | *PJM*

Stakeholders also unanimously endorsed revisions to Manual 11 and Manual 18 related to the business rules of public distribution microgrids at the Market Implementation Committee meeting Wednesday.

The Manual 11 revisions included provisions for reflecting islanded conditions in resource availability for energy and ancillary services, Tacka said, while the Manual 18 language adds clarification for performance assessment interval treatment of public distribution microgrids serving as capacity resources.

All three manual changes now move on to the Markets and Reliability Committee for a first read at its Dec. 17 meeting and PJM seeking endorsement at the January meeting.

COVID-19 Update

Paul McGlynn of PJM provided an update on the RTO’s operations plan in response to the COVID-19 pandemic, saying it is looking to institute more restrictive measures as the number of cases rises across Pennsylvania and the region.

McGlynn said PJM has decided to push back its return-to-campus plan to May 31. In-person stakeholder meetings will not resume before July, McGlynn said, and will continue to be held virtually.

PJM’s Annual Meeting will also be held virtually in May. McGlynn said the RTO expects to deal with the impacts of the pandemic well into 2021.

“When you hear about it every day, it’s easy to lose track or not appreciate the rate of changes in some of what’s going on,” McGlynn said.

PJM staff have been “doubling down” on social distancing efforts and cleaning protocols in place since they were implemented in March, McGlynn said. Additional cleaning is being conducted in the control rooms, McGlynn said, and changes were made to the air filtration systems.

McGlynn said strict social distancing policies are in place in the control rooms, and staff have been further spread out to limit contact. He said the real-time reliability engineers have been moved off the control room floor and on to the mezzanine level of the Valley Forge, Pa., campus to enhance social distancing.

PJM Senior Engineer Bilge Derin presented an administrative change to Manual 1 Attachment F, a temporary attachment added in April that outlines requirements for non-traditional control room setups during the pandemic. The attachment includes language on communications, redundancy, and cyber and physical security.

The attachment was set to expire on Dec. 31, Derin said, but the change will extend the measures until June 30, 2021.

McGlynn said PJM is also conducting discussions with the Electric Sector Coordinating Council over distributing a COVID-19 vaccine to critical personnel when a vaccine is available.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked if any consideration is being given to sequestering control room staff on the campus as it was done in spring at the height of the pandemic.

McGlynnn said there are “active discussions” going on by PJM staff about another possible sequestration. He said dispatchers were originally sequestered for around 10 weeks in the spring.

“I think it’s likely to be driven based on the data and the numbers of infections we are seeing,” McGlynn said.

SRCS Sunset Proposal, SOS Charter Review

Brian Lynn of PJM reviewed a proposal to sunset the System Restoration Coordinators Subcommittee (SRCS), which was originally created in 2012 but has not met since February 2019.

Lynn said the SRCS previously addressed unique responsibilities among PJM subcommittees, including administering, coordinating and debriefing restoration drills conducted within the RTO footprint. It also served as point for system restoration-related issues, made recommendations for changes to Manual 36 and conducted an annual review of each member company’s restoration manual as required by NERC standards for how they will respond to system disturbance conditions or a blackout.

Lynn said PJM staff have acknowledged that the subcommittee’s listed responsibilities are all important, but all of its work are currently supported by other groups. The sunsetting of the SRCS would reduce duplicative work and meetings, he said.

Much of the subcommittee’s work is now conducted at the Dispatcher Training Subcommittee, the System Operations Subcommittee (SOS) and the PJM Transmission Operations Department, Lynn said.

The OC will be asked to endorse the proposal at its Jan. 13 meeting.

Paul Dajewski of PJM also reviewed the proposed charter update for the SOS. The updates involved minor changes as part of the annual review process.

PJM removed a reference to the SRCS because of the sunset proposal. The changes also include referring to “user groups” as “forums” and the addition of the eDART XML Forum as a group established to assist the SOS in carrying out its responsibilities.

The OC will vote on the changes at its next meeting.

December 8, 2020

PJM PC OKs RTEP Rules for SATA

Stakeholders endorsed PJM’s proposed rules for how storage should be considered in the Regional Transmission Expansion Plan (RTEP) process at last week’s Planning Committee meeting.

The PJM proposal, which includes criteria to be used in evaluating storage as transmission assets (SATA) to address reliability, market efficiency, operational performance and public policy, passed with 58% approval, including 91 “yes” votes. In a follow-up nonbinding poll, stakeholders endorsed the proposal over maintaining the status quo with 51% support, or 90 “yes” votes.

Jeffrey Goldberg of PJM reviewed the RTO’s package, saying no changes were made since it was presented at last month’s PC meeting for a first read. (See PJM Moves Closer to Endorsing SATA.)

The package establishes requirements to ensure implementation maintains system reliability consistent with NERC standards. The SATA evaluation approach also seeks to ensure there are no adverse impacts to the generation interconnection queue, Goldberg said.

The package only focused on SATA in Phase 1 of the stakeholders’ discussions, he continued. They will take up the issue of dual use for storage in Phase 2.

“We want to point out that SATA is a generator at times; it’s a load at other times, and it can be modeled as different types of components,” Goldberg said.

SATA Background

Michele Greening of PJM’s stakeholder affairs reviewed the work completed at the SATA Special Planning Committee sessions that began in June after stakeholders approved the issue charge in May. (See SATA Issue Charge Moves Forward in PJM.)

Phase 1 of the effort explored existing transmission planning criteria, including the performance measurement methodology and where there were gaps in planning.

PJM included a draft version of associated Operating Agreement language for informational purposes at the PC meeting. A first read of the proposed solution package and the supporting OA language is scheduled for the Market and Reliability Committee meeting Jan. 27.

Stakeholder Discussion

Sharon Segner, vice president of LS Power, asked if PJM was looking to amend Tariff language along with the OA in the package.

PJM attorney Pauline Foley said the RTO was attempting to pair the definitions of generating facilities and SATA with the Tariff language. She said the definitions will be contained in the Tariff.

Foley said stakeholder requests to PJM prompted the RTO to include the draft OA language for the PC meeting.

PC Chair Dave Souder said PJM will welcome feedback on the OA language going into discussions and the first read at the MRC. Souder said PJM plans to schedule another SATA working group meeting to talk through the concepts and language proposed for the OA.

“We have time to solicit feedback and modify that in advance of the MRC,” he said.

PJM SATA — Carl Johnson, PJM Public Power Coalition | © *RTO Insider*

Carl Johnson of the PJM Public Power Coalition said it wasn’t clear if the components in the PJM package would apply to supplemental projects as they do to reliability projects. Johnson said stakeholders needed clarity on the design components.

PJM’s Aaron Berner said the SATA discussions related to mitigation and reliability issues, not to supplemental projects. He said the intent of the SATA discussions was about how PJM would evaluate projects in the RTEP as potential solutions to reliability violations.

Berner said if there was any confusion around the proposed language, it could be modified before a vote at the MRC.

Bruce Campbell, director of regulatory affairs for CPower, asked if the PJM package will accommodate an aggregation of storage resources as outlined in FERC Opens RTO Markets to DER Aggregation.)

Berner said the dual use aspect of SATA, which is relevant to Order 2222, will be discussed in Phase 2.

Campbell asked if there was any intent of PJM to review the market components of SATA with members of the Market Implementation Committee. He said he remains a “bit uncomfortable” with the concept that a SATA resource could be active in markets.

Berner said the implications of SATA on markets have been discussed by PJM staff and will play a role in Phase 2 discussions. PJM said that Phase 1 reliability requirements must be established to ensure Phase 2 dual use does not adversely impact reliability. SATA models will appear in the base case in standby and be represented in sensitivity cases as both a generator and a load.

December 8, 2020

PJM MIC Briefs: Dec. 2, 2020

PJM’s Market Implementation Committee advanced manual language to the Markets and Reliability Committee regarding a stability limits capacity constraint proposal despite the objections of stakeholders who attempted to overturn the decision.

PJM Market Implementation Committee — Joe Ciabattoni, PJM | © *RTO Insider*

Joe Ciabattoni, PJM manager of interregional market operations, reviewed proposed updates to Manual 3: Transmission Operations; Manual 11: Energy & Ancillary Services Market Operations; and Manual 28: Operating Agreement Accounting. He also reviewed proposed Operating Agreement revisions to reflect the capacity constraint and opportunity cost packages that were endorsed at the September MIC meeting. (See “Stability Limits Endorsed,” PJM MIC Briefs: Sept. 2, 2020.)

The proposals were the result of several months of discussion at the MIC on potential changes to how PJM curtails generating output in order to maintain stability during maintenance outages. Generating units must sometimes be reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could result in damage to the units. (See “Stability Limits in Markets and Operations,” PJM MIC Briefs: May 13, 2020.)

Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.

The capacity constraint proposal was put forward by PJM and the Independent Market Monitor and endorsed by the MIC with 64% support. It addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. Ciabattoni said the units would be dispatched in economic merit order up to the stated stability limitation.

If a unit chooses not to remedy a stability limitation identified during the planning process, its operating restrictions — as documented in its interconnection service agreement — would be invoked prior to those for other units, Ciabattoni said.

Lost opportunity cost (LOC) credits would not be paid for any reduction required to honor the stability limit. Similarly, LOC is not paid for economic megawatts of a resource that cannot produce because of a ramp limitation.

The opportunity cost proposal, presented by J-POWER and endorsed with 58% support, was fundamentally the same as the PJM-Monitor package except for providing compensation for LOCs. Paul Sotkiewicz of E-Cubed Policy Associates said payment for LOC is permitted by section 3.2.3 (f) of the Attachment K Appendix to the Tariff.

Ciabattoni said the proposed Manual 3, Manual 28 and Manual 11 language for the capacity constraint package clarifies that LOC will not be paid to the generator owners for reductions related to stability. It also includes Tariff language removing LOC eligibility from section 3.2.3 (f).

The alternate opportunity cost proposal had similar language in the three manuals but kept the Tariff language regarding LOC in place.

MIC Chair Lisa Morelli ruled that the manual language for both the capacity constraint and opportunity cost packages will move on to the MRC meeting on Dec. 17 for a first read.

Sotkiewicz made a request that the packages be voted on again at the MIC before being moved to the MRC. He said a September vote was “extremely close” and that PJM had stated “unequivocally” that Tariff and OA changes would be unnecessary in the capacity constraint proposal.

Morelli said it would be “extremely unusual” to vote again on packages already endorsed by the MIC.

Changes in Tariff and OA language would require a FERC filing and stakeholders may have voted differently on the packages with that knowledge, Sotkiewicz said, while the opportunity cost proposal did not require new OA or Tariff language.

Sotkiewicz registered a protest against Morelli’s decision to advance the manual language to the MRC, asking for a new vote on the packages given that ahead of the previous vote the proposal’s backers said there would be no need for Tariff or OA language changes. He said he believed the committee was not following the proper process under the rules of Manual 34.

“The vote was taken under a different set of assumptions about what was going to be required to make any changes,” Sotkiewicz said.

Tom Hyzinski of GT Power Group said he agreed with Sotkiewicz and that the addition of the Tariff language was an admission by PJM that the rules had to be changed as to not pay the LOC.

Stakeholders voted 63% against taking another vote on the packages, with 132 members voting “no” on Sotkiewicz’s protest.

Sotkiewicz said he appreciated PJM crafting manual language for the alternative opportunity cost proposal with members able to make a final decision between the two packages at the MRC.

“I think this is another area where the stakeholder process has failed us, and we’re going to have to revisit this,” Sotkiewicz said.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said advocates become frustrated when process issues take over substantive discussions at stakeholder meetings. He said the debate over the two packages was a “great example” of a process issue.

“The more we put in rules in the stakeholder process, it becomes a frustration when rules are used to frustrate a process,” Poulos said.

FTR Bid Limits Changes

Stakeholders endorsed a manual revision establishing bid limits for financial transmission rights (FTR) participants at the corporate entity level.

Brian Chmielewski, market simulation manager for PJM, provided an overview of updates to Manual 6: Financial Transmission Rights, which address the enforcement of FTR auction bid limits.

Chmielewski said the update included adding a bullet to Section 6.6 regarding “FTR Auction Business Rules” denoting the rule for FTR auction bid limits at the corporate entity level.

The new bullet reads, “In all FTR auctions, for each applicable auction round, total quotes (inclusive of buy bids, sell offers, and self-scheduled bids) for each effective FTR holder are limited to 10,000 MWh for each available auction period.”

Chmielewski said the FTR group will communicate the changes to the FTR Center, PJM’s tool that market participants use for submitting bids into the auctions prior to it going live. The information will be presented at the Tech Change Forum on Dec. 15.

A final vote is scheduled for the January MRC meeting.

Sotkiewicz asked why a limit is being proposed and why it was set at 10,000 MWh.

Chmielewski said it’s been PJM’s policy to maintain a 10,000 MWh bid limit so that the auction software would function properly. He said a limit had to be created to ensure the software would solve problems on time.

PJM has seen sub-accounts created in the last few years to get around the 10,000 MWh limit, Chmielewski said, with some corporate entities setting up multiple sub-accounts that are able to submit more bids and creating “inequities” among market participants.

Chmielewski said the concept was to memorialize the 10,000 MWh number in the manual language so it becomes a business rule everyone’s aware of and to also change the software so it won’t be possible to get around the limit by creating additional sub-accounts.

Sotkiewicz asked if it would be possible for PJM to look into further software solutions that would be able to handle higher limits and navigate through current programming constraints.

“With advanced software, don’t we think it’s time to move into the 21st century?” Sotkiewicz asked.

Chmielewski said PJM has committed to looking at stress testing the software and potentially increasing the limit.

UTC Uplift Changes

Stakeholders unanimously endorsed manual updates resulting from a recent FERC order addressing the allocation of real-time and day-ahead uplift to up-to-congestion (UTC) transactions.

Ray Fernandez, manager of market settlements development with PJM, presented the updates to Manual 28: Operating Agreement Accounting to conform with changes ordered by FERC regarding uplift charges on UTC transactions (EL14-37).

In its order issued in July, FERC determined that PJM’s current uplift allocation rules are unjust, unreasonable and unduly preferential because they do not allocate uplift to UTCs. (See FERC Orders Uplift Charges on PJM UTCs.)

PJM was directed by the commission to submit a replacement rate that revises the RTO’s current uplift allocation rules to allocate uplift to UTCs “in a manner that treats a UTC, for uplift allocation purposes, as if the UTC were equivalent to a [decrement bid] at the sink point of the UTC.”

Fernandez said UTCs will now be allocated for both real-time and day-ahead uplift.

December 8, 2020

Advocates Seek Bipartisan Support for Energy Efficiency

Decarbonization advocates said last week they hope energy efficiency is one issue that will attract bipartisan support in a narrowly divided Congress in 2021.

Bipartisan Energy Efficiency — U.S. Rep. Paul Tonko (D-N.Y.) | *ACEEE*

“Regardless of the outcome of the special [Senate] elections in Georgia, we are going to have some very narrow margins in both the House and the Senate,” U.S. Rep. Paul Tonko (D-N.Y.) told the American Council for an Energy-Efficient Economy’s (ACEEE) Energy Efficiency and Climate Policy Forum on Thursday. “It is my hope that with the weight of the White House, coupled with its executive agenda, we will be able to do more than you might expect.”

Tonko, chair of the House Energy and Commerce Committee’s Environment and Climate Change Subcommittee, said President-elect Joe Biden’s top priorities for 2021 should include getting the Department of Energy’s Office of Energy Efficiency & Renewable Energy (EERE) “back on track.”

“DOE will need more resources and personnel,” he said. “EERE’s employment levels are more than 180 [full-time equivalents] below fiscal year 2013 levels.”

Tonko also said he held out hope that Congress might approve some energy efficiency legislation before the lame duck session ends this month. “Currently people in both chambers are working to reach agreement on an energy package for an end-of-year bill. I don’t want to suggest that it will be the bold suite of clean energy priorities that I want to see advanced. And it is far from certain that anything will be able to be enacted. But the good news is energy conservation measures have always enjoyed strong bipartisan, bicameral support in Congress. So, if any energy policies move this month, there’s a good chance some efficiency and [research and development] provisions will be part of it.”

The daylong conference also included discussions on decarbonizing industry, transportation and buildings.

New York Moving on Building Emissions

Janet Joseph, senior vice president of strategy and market development for the New York State Energy Research and Development Authority (NYSERDA), noted that 70% of the state’s building stock was constructed before they were subject to energy standards. The impact? Space and water heating is the state’s single largest source of greenhouse gas emissions, she said.

In response, the state plans to electrify all heating and cooling, make buildings more energy efficient and incorporate more load flexibility into them, Joseph said. “This will become really significant, as we will need to accommodate an electric supply that is largely powered by intermittent renewable resources.”

Joseph said NYSERDA will release its “Carbon Neutral Buildings Roadmap” early next year. By 2030, more than half of heating systems installed in New York will need to be heat pumps; by 2050, nearly all new systems must be heat pumps powered by carbon-free electricity, Joseph said. “Air-source heat pumps, ground-source heat pumps, heat pump hot water heaters [and] high-efficiency systems that can work in cold climates.”

But despite providing heat pump incentives for several years and supporting pilot programs, only about 3% of the state’s homes are using heat pumps for heating. “So, we are clearly at the beginning of a major transformation in how we heat and cool our buildings,” she said.

In April, officials announced New York State Clean Heat, which will include almost $500 million in consumer incentives to be distributed by utilities. It also includes about $200 million in spending by NYSERDA to improve consumer awareness of improvements in heat pump technology and reduce their costs by 25% while increasing the pool of labor to install them by more than 14,000 workers.

The goal, Joseph said, is to position “the state for more affirmative regulatory action that will send a clear market signal for all-electric buildings in the future.”

“We will need regulatory changes through building and construction codes, appliance standards and/or greenhouse gas emission standards that set a clear market signal with a date certain to drive building electrification at the scale and pace we need to achieve our climate goals.”

She said the state also will launch a demonstration initiative next year focused on community-scale district geothermal systems. “We need heat pump solutions that can scale,” she said.

It is also partnering with the real estate industry in seeking decarbonization strategies for tall buildings in New York City and elsewhere, through the Empire Building Challenge.

“We will need low-cost capital, and lots of it, to support investments on the scale of what has been mobilized to support clean water infrastructure in this country. … We will also need continued innovation in these technologies to drive performance and cost improvements, and specifically getting at hard to electrify buildings. There will be some buildings, at least in New York state, that will be very hard to electrify.”

Building Codes

ACEEE Executive Director Steve Nadel also took up the subject of building codes, noting that the “energy use index” for commercial buildings has been reduced by about 50% since 1975, with somewhat smaller cuts for residential buildings, as a result of tightened state and local building codes. New model codes by the American Society of Heating, Refrigerating and Air-Conditioning Engineers and the International Energy Conservation Code (IECC) appear to require “significant” additional savings, he said.

But Nadel said legislation to tighten federal code goals have been opposed by homebuilders, whose dominance of the IECC has prevented faster progress.

New and existing residential and commercial buildings, 2020-2050 | *ACEEE*

“There may be some questions about whether the IECC process is fair or whether we need an alternative,” he said. “This year, the membership effectively overrode [the homebuilders]. We’ll see what the process is going forward and whether the IECC process is workable, or whether we need to be looking for alternatives.”

Decarbonizing Manufacturing

The conference also heard from Tom Dower, senior director of government relations for ArcelorMittal, a steel producer and mining company with industrial operations in 18 countries, who briefed ACEEE on the company’s commitment to net-zero emissions by 2050.

In Europe, where most of the company’s operations are located, it has pledged a 30% emissions reduction by 2030, a “very aggressive [goal] for a steelmaker,” Dower said.

He said the company was hoping to pioneer a carbon-neutral method for steel and ironmaking. But, he said, “new policy frameworks will be required to ensure the transition to carbon neutrality is both competitive and technically possible,” decrying the U.S.’ lack of a “coordinated, coherent climate strategy.”

“We’re working in industries that have long investment cycles, and it’s unclear right now whether the market will reward early movers. [It] can require a leap of faith for those who want to make the right steps towards decarbonization but are in a market environment today [in which they] may be harmed economically.

“Uncertainty,” he added, “is not helpful in terms of leadership and making difficult decisions.”

December 8, 2020

NY Utilities Diverge on Managed EV Charging

New York’s six local distribution companies split over whether to adopt “passive” or “active” approaches to managing electric vehicle charging in proposals submitted to the New York Public Service Commission last week (18-E-0138).

The PSC ordered the companies on July 16 to submit proposals for managed charging programs for mass market customers. (See NYPSC Approves $700 Million for EV Chargers.)

Orange and Rockland Utilities and Central Hudson proposed passive, or behavioral load control programs, such as time-of-use (TOU) rates to affect charging patterns. Consolidated Edison has been running a passive program since 2017.

National Grid’s Niagara Mohawk Power is proposing active managed charging, also known as direct load control.

Avangrid’s New York State Electric and Gas (NYSEG) and Rochester Gas and Electric (RG&E) are proposing use of both.

Niagara Mohawk said an active managed charging program will produce greater benefits than a passive program, including “avoiding timer peaks, shifting an even greater portion of EV charging off-peak, and anticipating other managed charging use cases envisioned to support a clean energy future.”

The utilities also differed over use of on-vehicle telematics — an onboard tracking system that sends, receives and stores telemetry data — or networked Level 2 (L2) chargers.

Level 1 chargers supplied with most EVs connect to a typical residential 120-V outlet and can deliver about 4 miles of charge per hour depending on the amperage rating of the circuit, enough to meet the needs of an EV driver whose round-trip commute is less than 30 miles daily.

L2 chargers, which require a 240-V outlet, are five times as powerful, providing 25 mph of charging, but a charger and installation can cost about $1,400.

NYSEG, RG&E

NYSEG and RG&E said they prefer data collection via telematics because it is cheaper than networked L2 chargers and allows collection of charging data, and the ability to initiate DR events, regardless of where the car is located within their service territories.

The companies also said residential L2 chargers can force distribution system upgrades due to their greater power requirements. “Typical residential L2 chargers have power ratings of approximately 7 kW, while a typical residential transformer is rated for approximately 25 kW and can serve five to 10 households. Wide scale deployment of unmanaged residential L2 charging would generate the need for the upgrade of, or installation of, additional transformers and potentially feeder upgrades depending on loading conditions,” they said.

New York EVs — Illustrative EV customer types, as identified by the Smart Electric Power Alliance | *Smart Electric Power Alliance*

The two utilities, which have almost 1.3 million electric customers, proposed three choices for EV drivers.

The “basic” level would require participants to provide the companies with limited demographic and charging behavior information, to enroll in their EV TOU rates, and to receive behavior prompts to charge during off peak periods. They would receive a $25 annual incentive.

Drivers choosing the “intermediate” option agree to allow the utilities to receive charging data via a telematics device they install in their EV or through their vehicles’ on-board telematic systems in return for a $50 annual incentive. They can receive an additional $50 per year if at least 90% of their charging occurs during off-peak hours. They must agree to enroll in demand response but are not required to respond to any event called by the companies; those that do would receive a $20 incentive for each event they opt-in to.

“Advanced” level participants will enroll in active managed charging in which they determine the level or state of charge required and the times their vehicle is available for charging. The companies’ managed charging algorithm will combine the charging power requirements and session duration to determine how much power to deliver each participant and when. Interaction between participants and the utilities will be automated through a web-based portal or mobile app. Incentives would be based on the energy and time requirements of each participant, ranging from $24 to $70 annually.

The companies based their proposal in part on NYSEG’s OptimizEV pilot, which began in March with 35 participants, equal to 10% of the EV owners in the company’s smart meter footprint in 2017.

The companies said initial results of the program indicate that managed charging can avoid the “timer peak” — when demand spikes in the first minutes of off-peak pricing under TOU rates. They proposed an $11.8 million budget for 2021-2025.

O&R, Central Hudson

Orange and Rockland (O&R), which has less than 233,000 electric customers in the state, proposed enrolling 100 participants per year in a three-year program costing about $800,000 as a supplement to its existing TOU rates.

It proposed a $150 enrollment bonus and up to $500 annually for participants who charge their EVs during off-peak periods: $5/month for using company-provided hardware or software to monitor charging behavior, $0.10 per kWh of charging during off-peak hours, and $20/month when they avoid charging during peak hours (2:00 pm to 6:00 pm) on summer weekdays.

Fortis’s Central Hudson also proposed building on the passive managed charging programs it has offered since 2019, a whole home TOU rate and an EV meter TOU rate.

The new program would require customers to procure a networked home charger allowing them to schedule their charging and participate in DR programs. They would receive a bill credit for charging during off-peak hours based on the difference between the average energy rate and the off-peak rate. The company said it would fund the credit through its revenue decoupling mechanism.

It also said it is considering the addition of active managed charging within the non-wires alternatives (NWA) program it began in 2016, which uses distributed energy resources including demand response to defer or eliminate infrastructure upgrades. “Primary considerations will be coincidence of baseline charging loads with locational peaks, magnitude of available curtailment, and cost of implementation and customer incentives,” it said.

The utility said it would not set “hard targets” for the initiative because of the limited number of registered EVs within its territory — 1,162 battery electric vehicles (BEVs) and 1,343 plug-in hybrid EVs (PHEVs) — and the recent decline in new EV registrations.

Consolidated Edison Company of New York

Con Edison’s SmartCharge New York program rewards EV owners with “off-the-bill” incentives for charging during off-peak hours. Initially limited to light-duty EVs, it was expanded in 2018 to medium- and heavy-duty EVs.

The program uses onboard vehicle telematics, smart charging stations, submetering and the FleetCarma connected car device, which most light-duty participants in the program use. The device, which plugs into the onboard diagnostics port of the vehicle, collects charging data, charging rate and total energy consumed during each charging session. EV owners receive cash incentives via PayPal.

Con Edison, which has 3.3 million electric customers, paid EV owners using FleetCarma $631,000 in incentives from Jan. 1 to Oct. 30 of this year, up from $65,000 in 2017. Light-duty EVs using FleetCarma have grown to 2,342 from 416 in 2017.

Light-duty EV owners using FleetCarma receive a $150 enrollment bonus, $5/month for at least one charging event in Con Edison territory and $20/month for avoiding summer peak charging.

The company said the flexibility of its program has resulted in increased enrollment. “For example, the program does not require the EV owner to install additional electrical equipment (such as a panel or meter) to participate in the program. SCNY participation is also not restricted to Con Edison account holders or home charging. Many Con Edison customers charge their vehicles at locations that are not associated with their Con Edison account and the person making the charging decision may be different from the one responsible for the electric bill. By allowing this flexibility, SCNY allows the company to manage EV load of any EV owner who charges in Con Edison’s service territory.”

It said it is considering new ways to enroll additional EV owners and lower per-vehicle acquisition costs, as well as new technologies for monitoring charging.

Niagara Mohawk

Niagara Mohawk, which has 1.7 million electric customers, proposed an active managed charging program to supplement programs it included in a rate case filing in July (Case #20-E-0380).

The new proposal would offer $500 rebates for purchasing L2 chargers and include telematics-based charging, which it said, “is expected to increase program enrollment and reduce the program cost-per-enrolled customer.”

It said most BEVs, including models from BMW, General Motors, Hyundai, Jaguar/Land Rover, Nissan, Tesla and Volkswagen/Audi, support active management.

The utility currently does only passive managed charging through its SC-1 variable time of use (VTOU) rate, which it said “has several hundred known EV drivers enrolled, a relatively small share of the total EVs in the company’s service area.”

National Grid’s affiliate in Rhode Island also has a passive managed charging program that provides enrollment incentives and per-kWh rebates. The company said preliminary results of an evaluation of the Rhode Island program showed a statistically significant increase in off-peak charging between participants that received off-peak rebates versus those that did not.

“For BEVs and PHEVs, there was a persistent amount of on-peak charging that participants who received the off-peak rebates still did not shift off-peak,” the company continued. “These results suggested, among other things, that for future programs and rate designs, the company should investigate technologies and incentives to mitigate and manage any timer or rebound peaks induced from time of use rates (e.g., charging peaks at 9:01 P.M. as the off-peak window begins).”

Niagara Mohawk’s proposal would provide EV owners using networked L2 chargers or vehicle-based telematics a flat monthly price for at-home off-peak charging: $20 for up to 225 kWh or $25 for 325 kWh of off-peak charging.

In addition to the $500 rebate for installations of new L2 chargers, it will offer $150 to participants using telematics or an existing networked L2 charger.

The company would manage at-home charging during the off-peak hours (11:00 p.m. to 7:00 a.m.) by default, requiring a customer to override the utility schedule to charge during on-peak hours at home.

Including both L2 chargers and vehicle telematics is essential to broad participation because “neither has universal market coverage,” the company said. “Telematics provide greater present-day market coverage; however, networked L2 chargers provide a pathway for nearly any EV driver to participate.”

The company proposed a $3.2 million budget for fiscal years 2022-2025, saying it “is sized to support nearly 20% of the EVs on the road under a sales trajectory that meets the company’s portion of the state’s” goal of 850,000 EVs by the end of 2025.

December 8, 2020

NEPOOL Participants Committee Briefs: Dec. 3, 2020

The NEPOOL Participants Committee on Thursday approved updates to Forward Capacity Market (FCM) parameters for the 2025/26 capacity commitment period during its final meeting of the year.

The values, which passed the Markets Committee last month, won 71.84% support in a sector-weighted vote.

ISO-NE had updated the FCM parameters’ values since the November MC meeting as it recalculated offer review trigger prices (ORTPs) to account for the combined effects of the supported amendments. Two of the amendments from the Union of Concerned Scientists reduced the offshore wind ORTP value to $0/kW-month.

The committee rejected the RTO’s original FCM parameters with only 18.33% of the sector-weighted vote, similar to its support at the MC meeting in November. (See “Amended Motion to Update FCM Parameters Passes,” NEPOOL Markets Committee Briefs: Nov. 9-10, 2020.)

The committee also rejected an amendment from Jericho Power on behalf of the New England Power Generators Association, with only 32.97% voting in favor. The amendment would have accounted for the impact net cost of new entry reference unit has on the Locational Forward Reserve Market (LFRM) clearing price by including the unit in the supply stack at its opportunity cost, which would have increased the net CONE value.

Energy Market Value Drops

ISO-NE COO Vamsi Chadalavada reported the energy market value for November was $197 million (through Nov. 23), down $42 million from October and down $142 million from the same month last year.

Natural gas prices were 4.7% higher from October to November, which pushed the average real-time hub LMPs to $27.10/MWh, up 0.8% from the prior month. Natural gas prices and LMPs were down 39% and 21%, respectively, from the same period last year.

Average day-ahead cleared physical energy during the peak hours as a percentage of the forecasted load was 99.6% during November, down from 100.8% during October, with the minimum value for the month of 95.3% posted Nov. 14.

Daily uplift, or net commitment period compensation (NCPC) payments, in November totaled $1.6 million over the period, down $1.2 million from October and down $2.1 million from November 2019. NCPC payments were 0.8% of the energy market value.

Cavanaugh Elected Chair

NEPOOL — David Cavanaugh, Energy New England | © *RTO Insider*

The committee elected Vice Chair David Cavanaugh, vice president of regulatory and market affairs for Energy New England, as its chair.

Previous Chair Nancy Chafetz of Direct Energy oversaw her final meeting and will remain one of the vice chairs. Other re-elected vice chairs included Doug Hurley, Synapse Energy Economics; Tina Belew, Massachusetts Attorney General’s Office; Frank Ettori, Vermont Electric Power Co.; and Michelle Gardner, NextEra Energy Resources.

Consent Agenda

The committee approved the consent agenda with one in opposition and some abstentions. It included support for ISO-NE’s plan for its third Order 841 compliance filing.

The RTO proposed Tariff changes to comply with three FERC directives. The first change removes Tariff language that could create a barrier to a storage resource’s market participation, effective in the first quarter of 2021. The second is the inclusion of four bidding parameters and a newly defined term that ISO-NE will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.

The RTO was expected to file this compliance with FERC on Monday.

2021 Budget

The PC unanimously approved a 2021 budget of $6,220,600 for NEPOOL, down $90,000 (0.9%) from 2020’s spending plan. NEPOOL expects to spend $5,654,000 by the end of this year, $711,00 less than the approved budget. Most of the decrease comes from a $515,000 decline in committee meeting expenses amid the COVID-19 pandemic as all gatherings became virtual events. Committee meeting expenses for 2020 include amounts to be paid to consultants for assistance with ISO-NE’s Future Grid Initiative. The budget also assumes no in-person meetings for the first part of the year.

December 8, 2020

Consumer Panel Discusses ISO-NE ‘Visions of the Future’

The ISO-NE Consumer Liaison Group last week held its final quarterly meeting of the year where a virtual panel of regional energy experts wrapped up 2020 and attempted to cast a hopeful look to 2021 as New England continues its transition to clean energy.

Robert Rio, senior vice president of government affairs and counsel at Associated Industries of Massachusetts, served as moderator for “Clean Energy & Regional Markets: The New England States’ and Other Visions of the Future.” He said the RTO must provide reliable and cost-effective power to preserve the wholesale markets, “all the while navigating the political minefields that are the New England states.”

In October, ISO-NE confronted a joint statement from five of the region’s six governors (Connecticut, Maine, Massachusetts, Rhode Island and Vermont) calling for market design, transmission planning and governance reforms, saying the RTO is frustrating their efforts to reduce economy-wide greenhouse gas emissions. The New England States Committee on Electricity, which represents the collective perspective of the region’s six states in the NEPOOL stakeholder process, also released a vision statement that detailed specific reform measures. (See States Demand ‘Central Role’ in ISO-NE Market Design.)

NESCOE Executive Director Heather Hunt said the “concepts and concerns” in the vision statement should not come as a surprise; “If there were easy solutions … we would have solved them by now.” Hunt said the governors’ joint statement “underscored their interest in better aligning our regional markets with the achievement of their collective and individual decarbonization goals and mandates.”

David Cavanaugh, vice president of regulatory and market affairs at Energy New England, said NEPOOL has worked with ISO-NE and NESCOE through the stakeholder process on the Future Grid Initiative, which includes a reliability study and potential pathways, the latter of which “looks to identify a framework that may facilitate the entry of state policy resources, such that we can avoid the double-pay issues folks are concerned about.”

‘Figuratively Screaming’

Doug Hurley, principal associate at Synapse Energy Economics, said for the past 16 years he’s spent his “time working with or directly for state agencies in most of the New England states on the cost of the wholesale electric grid and how to integrate clean energy into that system as quickly as possible.” He said states have been “figuratively screaming” at ISO-NE for years about the issues in the NESCOE vision statement and hopes the RTO recognizes its gravity.

RENEW Northeast Executive Director Francis Pullaro echoed Hurley’s comments, saying it is “an impressive accomplishment to get six states that have different constituencies and different interests from time to time, to be able to come together with a detailed vision.” He said the current power system was “designed for a different era” and the capacity market is “very costly to consumers.”

Clockwise from top left: Robert Rio, Associated Industries of Massachusetts; Robert Either, ISO-NE; Francis Pullaro, RENEW Northeast; Doug Hurley, Synapse Energy Economics; Heather Hunt, NESCOE; David Cavanaugh, Energy New England | *ISO-NE*

The capacity market “was put in place for a variety of reasons and some of those reasons have evolved over time, but basically it never contemplated a world of renewable energy at this scale, and you have now a lot of renewables coming in and not being able to participate in the capacity market and states wondering why [they are] paying for duplicative resources,” Pullaro said. “I think the old ways are just not suited for the future.”

Robert Ethier, ISO-NE’s vice president of system planning, said he looks forward to “figuring out with the states” what it will take to interconnect all the renewables they are seeking to contract over the next several decades.

“Clearly, that’s not going to be a one-shot deal,” Ethier said. “It’s going to be an evolving plan as we learn more, as additional contracts are signed, etc.”

According to Ethier, a 2019 NESCOE economic study looked at how much offshore wind could interconnect to the current grid.

“And the short answer is about 8,000 MW before things start to get really expensive,” Ethier said, adding that “2,500 to 3,000 MW” in Cape Cod “could easily cost $300-plus million to interconnect it to the existing system.”

“I think we all have to be cognizant of the fact that it’s going to be expensive to interconnect all these renewable resources,” he said. “The costs are going to go up dramatically once we sort of hit the limits of our current system, and we have to start building large new 345-kV lines or large underground lines or underwater lines. While all of us are going to work together in good faith, and we are going to try to develop things at least-cost, it will cost money to integrate all these renewables in a useful way.”

Pullaro said while ISO-NE has been successful with competitive markets to bring costs down, “what we’ve seen over the last 10 years or so in New England” is that states putting out their renewable energy goals to a competitive bid has also reduced costs.

Word from an ‘Energy Nerd’

When Rio posed a question about distributed energy resources (DERs), Hurley answered that “the challenges are numerous, and it would be hard to list all of them.”

“I would say first and foremost as part of this overall transition, it wasn’t what we originally envisioned when the markets and all the planning procedures were created,” Hurley said. “We’ve made a number of adjustments to those planning procedures and the markets to try to incorporate [DERs] better.”

He added that DERs provide “a whole bunch of opportunity” for participation by people who have small amounts of resources available to them like solar, wind or storage.

“It allows the opportunity for private businesses who are aggregators of those smaller resources together because even as much of an energy nerd as I am, I’m not going to try and enroll my solar panels directly into the ISO system, and put them in every day,” he said. “That’s just not a good use of my time. Even I would put them into an aggregation from something that some other company runs and put mine together with all my neighbors and then get that into the ISO systems in whatever way is appropriate.”

Finding the Pathway

Looking to 2021, Rio asked panelists what they think would be “really helpful” for the energy grid next year.

Cavanaugh, incoming chair of the NEPOOL Participants Committee, said New England has been struggling “with this tension of integrating state policy resources.”

“If 2021 was to have a success statement, it would be to find the appropriate pathways that balance investment, as well as state policy resources and achieving state goals, because you have to have a balance,” Cavanaugh said. “You still want to have the signals to draw merchant investment in the region because you need it, but you also need the ability to represent and respect state policy, so if ’21 could deliver anything, it’d be identifying a pathway that’s successful in achieving that goal.”

Either added that, “if we can achieve it, that would be fantastic.”

Hunt said that 2021 “is a year for a fresh look at what we’re asking the markets to do and how we’re governing how the markets operate.”

Pullaro said he could not help but look for sources of hope during the pandemic.

“So [my thought] for 2021 is to try and enjoy the fact that we’re at a point where we’re not arguing whether to transition to a clean grid, but how to do it,” he said.

December 8, 2020

NY Seeks ‘Just Transition’ in Decarbonization Plans

The New York State Energy Research and Development Authority (NYSERDA) this month issued a request for proposals seeking contractors to conduct site reuse planning studies for retired power plants.

The $5 million solicitation is just one manifestation of the huge effort the state is mounting to implement the Climate Leadership and Community Protection Act (CLCPA), which requires the state to switch to 100% zero-emission electricity by 2040 and reduce greenhouse gas emissions to 85% below 1990 levels by 2050.

At least 10 state agencies have roles in the transition, led by NYSERDA, the state Department of Environmental Conservation and the Climate Action Council, a 22-member committee that will prepare a scoping plan for achieving the state’s energy and climate goals.

The council’s work will be informed by more than 100 stakeholders — including manufacturers, farmers, generators, labor unions, environmental groups and trade associations — in advisory panels for Agriculture and Forestry; Energy Efficiency and Housing; Energy-Intensive and Trade-Exposed Industries; Land Use and Local Government; Power Generation; Transportation; and Waste. The RFP is related to the work of an eighth group reporting to the council, the Just Transition Working Group, which is considering issues of displaced workers, environmental justice and economic redevelopment.

At a meeting last week, the working group reviewed a straw proposal for the principles the state should follow, which it will present to the council on Dec. 15. In addition to the redevelopment of industrial communities, the 10 principles include topics such as “stakeholder-engaged transition planning”; preservation of culture and tradition; equitable access to “high quality, family-sustaining jobs”; climate adaptation planning; and protection of natural systems and resources.

Support for Power Plant Communities

The RFP is expected to result in $4.75 million in spending on consultants providing affected plant-site municipalities with technical assistance and $250,000 for a site reuse “toolkit” that could be used by other communities.

The deadline for responding is 3 p.m. Jan. 13; an informational webinar for prospective bidders will be held at 10 a.m. Dec. 15. NYSERDA expects to invite communities to apply for assistance in the first quarter of next year.

At the Just Transition Working Group’s meeting Thursday, Steve Ryan, director of business engagement for the state Department of Labor, briefed the panel on the department’s Rapid Response program, which offers résumé development, interview coaching and training opportunities.

New York Decarbonization — Workforce for New York’s traditional power generation (2016-2019) | *New York Just Transition Working Group*

The department had deployed the program for workers at the Somerset Operating Co., the state’s last coal-fired generating plant, which retired in March, and Indian Point nuclear plant, which shut down Unit 2 in April and will close its remaining unit next spring.

Ryan said the laid off workers appreciate the help. “We provide that hope. Because many of them have no idea where their next employment is going to be,” he said.

James Shillitto, president of the Utility Workers Union of America Local 1-2, which represented 400 workers at Indian Point, said site redevelopment is an easier challenge than retraining laid off workers and finding them new, well paying jobs. “Retraining workers is a little bit more difficult because you have people in various levels of their lives. You have the ones that need to hang on for five or six more years to retire, and the ones that are going to work another 20 to 25 years.”

The state Worker Adjustment and Retraining Notification (WARN) Act requires businesses to give 90 days’ advance notice for large layoffs or plant closures. “Typically, what happens with Rapid Response is it’s triggered by a WARN notice. But in these cases, as with Indian Point, we’re going to know well in advance what’s coming so we should have a framework where we can begin that process without waiting for a WARN notice,” Labor Commissioner Roberta Reardon said. “We need a long runway: as long a runway as we can get with both the employers and the workers to do the kinds of negotiating … or training to really have the best impact.”

Deliverables

Public Service Commission Chairman John B. Rhodes said the working group has two main deliverables, including an inventory of power plants at risk of closing, an effort to identify issues affecting plant site reuse.

The second deliverable is identification of problems and opportunities presented by site reuse. Among the problems: the local economic effects of lost salaries and reduced property tax revenues for local governments and schools. Also to be considered: environmental remediation and restoration.

Plant sites — often on lakes or rivers because of the need for cooling water — can be repurposed as parks or commercial or mixed-use developments. Their access to transmission lines and cooling water has also made them attractive to data centers — a use the owners of the Somerset plant are pursuing. They can also provide interconnection points for new renewable generation.

Jobs Mapping

The state also has begun early work on an assessment of job-loss-threatened power plant workers’ skills to identify retraining paths and match them with job openings in clean energy and elsewhere.

As of 2019, the state had 800 workers in oil-fired generation, almost 5,400 in natural gas and more than 3,800 in nuclear. It also had more than 65,000 workers in transmission and distribution.

As of 2018, 76 of New York’s 106 gas turbines (2,356 MW) were older than 46 years; nationally, 95% of such units have deactivated by this age. Similarly, 95% of steam turbines nationally retire by age 62.5. By that measure, 11 out of 46 units (866 MW) are at retirement age. By 2028, more than 8,300 MW of gas and steam turbine-based capacity in New York will hit retirement age.

About 35% of the state’s generating capacity has been added since 2000. “There’s been in recent years about 2,000 MW of natural gas combined cycle generation [added],” Emilie Nelson, executive vice president for NYISO, told the working group. “The plant staffing required for those types of facilities tends to be lesser than some of the older plants. We have about 2,000 MW of large-scale wind on the system. A lot of the solar that we have thus far is behind the meter, so [it requires] a little different type of support from a job perspective.”

Policy Drivers

In addition to the CLCPA, New York’s transition is being driven by Regional Greenhouse Gas Initiative regulations adopted Dec. 1 to reduce the carbon dioxide emissions cap by 30% from 2020 to 2030. The changes also expand the program to cover peaking units above 15 MW, a reduction from the current 25-MW threshold.

The Department of Environmental Conservation’s “peaker rule” will be phased in between 2023 and 2025, affecting 3,300 MW of capacity. The rule has two compliance options for plants that cannot meet emission limits on pounds of NOx per megawatt-hour: stopping operation during summer ozone season, or replacing their output with energy storage or renewable generation at the same interconnection.

The 2020 NYISO Reliability Needs Assessment identified transmission security needs beginning in 2024 and resource adequacy needs by 2027. The ISO’s first quarterly short-term assessment of reliability (STAR) report found an additional transmission security need in New York City for 2023. In addition, city regulations will bar combustion of Nos. 6 and 4 fuel oil by 2020 and 2025, respectively, affecting 2,946 MW.

“This is manageable if we’re thoughtful and look ahead,” Rhodes said.

Putting it All Together

Lara Skinner, executive director of The Worker Institute at Cornell University, which performs research and education on current labor issues, noted that the Labor Department’s Rapid Response program was created to respond to individual business closures. “When we think about this transition to a zero-carbon economy, we’re taking about a massive transition. A major economic transition with significant labor, social, community impacts — economic impacts,” she said.

Skinner suggested panel members review U.S. Sen. Tammy Duckworth’s (D-Ill.) proposed “Marshall Plan for Coal Country Act,” which would modify bankruptcy rules to require companies that shut down to provide health care and pension benefits to former workers and give free tuition at public colleges for their children.

“Today’s meeting demonstrates to me that there’s some really great thinking happening around the broader impact of the transition in New York state,” Skinner said. “For me, it raises the question of how do we link all of this up? And how do we think bigger and broader about this transition and make sure that our approach to the transition is going to be comprehensive and cohesive?”

December 8, 2020

FBI Sees No Rest from Cyber Battles in 2021

FBI Cybersecurity — Manny Cancel, NERC | *NERC*

Foreign adversaries continue to hone their cyber threat strategies against the North American bulk power system, cybersecurity experts told the Midwest Reliability Organization’s (MRO) Annual Member and Board of Directors Meeting on Thursday.

“The bad guys have not taken the pandemic off; they’ve seen it as an additional opportunity to exploit or do more harm to the sector,” said NERC Senior Vice President Manny Cancel, the CEO of the Electricity Information Sharing and Analysis Center (E-ISAC).

Cancel joined Joel Max, energy sector and control systems lead at the FBI’s Cyber Division, to brief MRO’s members and directors on the current threat landscape and the government’s efforts to help utilities fight back.

Iran Tensions Lead Immediate Concerns

According to Max, the most prominent state-backed cyber threats against the BPS continue to originate from Iran, Russia and China.

Iran seemed to loom large in the minds of several attendees at the meeting, who asked about the likelihood of threats originating from recent tensions between it and Israel, which is believed to have been behind the assassination of Iran’s top nuclear scientist Mohsen Fakhrizadeh on Nov. 27. Similar fears arose after the U.S. drone attack that killed Iran’s Maj. Gen. Qassem Soleimani on Jan. 2. (See Iran Cyber Threat Increasing, Experts Say.)

Max acknowledged that Iran is known to have the capability for “localized, temporary disruptive effects against corporate networks;” the 2012 attack on Saudi Arabia’s national oil company Saudi Aramco is believed to have been carried out by hackers backed by Iran. Iran is also believed to have carried out damaging cyber operations within the U.S., targeting the tourism and financial services sectors, along with gaining access to the supervisory control and data acquisition system for the Bowman Avenue Dam in Rye, N.Y.

While Max assured attendees that “we don’t have any indication of [an] imminent [threat],” he reminded them that this is a “time of turbulence,” with both the ongoing COVID-19 pandemic and the transition to a new U.S. presidential administration creating distractions that adversaries may want to take advantage of. Entities must remain vigilant for any opportunistic actions, he said.

Spies and Saboteurs Probing Weaknesses

Like Iran, Russia’s cyber activities targeting the U.S. energy sector include both “reconnaissance [and] future attacks,” Max said. He reminded participants that Russian hackers have gained access to networks used by both large and small players in the energy sector, gaining success in recent years by finding weak links among vendors or service providers that have not put in the same level of effort as utilities themselves.

“The way you get to the bigger fish is by going through the smaller ones, who may not have the same resources or cybersecurity posture as your company,” he said, noting that even “a vendor that only supplies one piece of software [or] does some sort of maintenance on your system” could provide an entry for a determined and patient intruder.

China, too, appears to have built a highly successful clandestine operation for finding and exploiting weak points in supply chain networks. Unlike Iran and Russia, the nation’s intentions toward the U.S. grid seem primarily focused on industrial espionage rather than sabotage. Max listed renewable energy technology as a key focus for Chinese hackers, reflecting the renewable energy priorities laid out in the Chinese government’s 13th Five-Year Plan.

Feds Seek to Make Hackers Hurt

Max said the U.S. government is taking an active role in combating cyberattacks through a program of “imposing risk and consequence on the adversaries.” This approach includes actions against individuals, such as the indictment earlier this year of six Russian military intelligence officers for attacks against the Ukrainian power grid in 2015 and 2017. (See Six Russians Charged for Ukraine Cyberattacks.)

Max said sanctions against organizations can also be effective tools. In October, the Treasury Department announced economic sanctions against Russia’s “State Research Center of the Russian Federation FGUP Central Scientific Research Institute of Chemistry and Mechanics (TsNIIKhM).” The government-backed institution is believed to be behind the Triton malware that corrupted industrial control systems at a petrochemical facility in the Middle East in 2017 and was accused of targeting at least 20 electric utilities in the U.S. last year.

Chinese organizations believed to support the government’s cyberespionage campaigns have also been targeted. Most prominent among these is Huawei Technologies, indicted in New York in February for conspiring to steal trade secrets from U.S. companies. Huawei makes a wide range of technology products for both consumers and businesses and has been the target of several warnings and inquiries this year, including a Notice of Inquiry from FERC Opens Supply Chain Cyber Risk Inquiry.)

“If we as the FBI can impose consequences on the adversaries, we’re hoping that that deters activity against you as U.S. companies, but also makes it more difficult [and costly] for an adversary … to undertake any sort of attack against your systems or your assets,” Max said.

December 7, 2020

UPDATED: PG&E Gets $1.3B Rate Hike, Cancels Mass Blackouts

Pacific Gas and Electric canceled forecasted blackouts Monday after saying it might shut off power to nearly 400,000 residents to prevent wildfires. The move would have been an extraordinary step in December, when fire season is normally over in the utility’s Northern California service territory.

Over the weekend, Southern California Edison and San Diego Gas & Electric instituted public safety power shutoffs (PSPS) in their service territories that affected roughly 85,000 customers, or nearly 250,000 residents, as hot dry Santa Ana winds created dangerous fire conditions.

PG&E predicted mass blackouts Friday, a day after the California Public Utilities Commission unanimously approved the utility’s 2020-2022 general rate case. The decision included a nearly $1.3 billion, three-year rate increase, much of it meant to help the utility prevent wildfires and limit the extent of PSPS events.

“This decision provides significant funding for PG&E’s Community Wildfire Safety Program,” Commissioner Liane Randolph said. “The CWSP incorporates a risk-based approach to identify and address PG&E assets that are most at risk from the threat of wildfires and associated events.”

PG&E Safety Blackouts — PG&E on Dec. 5 said it could shut off power to 92,000 customers in 16 counties on Dec. 7. | *PG&E*

The CPUC approved $603 million in 2020, $930 million in 2021 and $1.5 billion in 2022 in total funding for the wildfire program. PG&E said it will use the funds for enhanced vegetation management and system hardening, including installing stronger poles and trimming branches from an estimated 120 million trees.

The commission authorized a $9.1 billion revenue requirement for PG&E in 2020, a $584 million increase over 2019 but $474 million less than the utility’s initial request. Increases of $316 million and $364 million for 2021 and 2022, respectively, will follow. PG&E and consumer groups reached the final amounts in a settlement approved by the CPUC.

Randolph noted that nearly $3 billion of PG&E’s wildfire mitigation work is excluded from its rate case by Assembly Bill 1054, passed last year. The bill prohibits the state’s three large investor-owned utilities from earning a return on equity for their combined share of the first $5 billion spent on wildfire-prevention measures.

The CPUC also approved a settlement provision that allows PG&E to recover up to $1.4 billion in annual insurance costs.

The settlement and commission’s decision followed 17 community meetings held throughout PG&E’s service territory and four weeks of evidentiary hearings.

The utility’s equipment started devastating fires in 2017, 2018 and 2019 that killed more than 100 residents and destroyed tens of thousands of structures, the California Department of Forestry and Fire Protection found. The department is investigating PG&E for starting another wildfire in September that killed four people and burned more than 200 structures in rural Northern California. (See PG&E Under Scrutiny in Deadly Zogg Fire.)

In a recent letter, CPUC President Marybel Batjer threatened to institute a new process of increased oversight of PG&E for what she said were serious lapses in the utility’s vegetation management. (See related story, PG&E Faces ‘Enhanced Oversight’ by CPUC.)

Critics have said the company put shareholder profits over grid maintenance for decades.

“Unfortunately, this summer has showed us again that PG&E is still behind in the investments needed to … make [its] system and vegetation management safe,” Commissioner Martha Guzman Aceves said. She said she would support PG&E’s rate increase for safety reasons despite it coming during a pandemic and economic downturn, when many residents will feel the increase more.

December Fire Conditions

In its initial PSPS statement last week, PG&E said it might shut off power to 130,000 customers — or about 377,000 residents, based on average household size — in parts of 15 counties.

“Dry conditions combined with expected high wind gusts pose an increased risk for damage to the electric system that has the potential to ignite fires in areas with dry vegetation,” the utility said in a news release.

It reduced the number Saturday to 92,000 customers, or about 267,000 residents, after receiving updated weather forecasts. It then cut the number of customers potentially affected by 90% Sunday and canceled the blackouts altogether Monday, citing improved weather.

In a separate statement on its rate case, PG&E said the CPUC’s decision will allow it to keep future PSPS events smaller and shorter.

The late fall fire conditions also impacted dryer Southern California, which has had catastrophic fires in December in recent years. The blazes included the 2017 Thomas Fire, blamed partly on Southern California Edison equipment. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)

SCE said Monday it had shut off power to about 12,000 customers for safety reasons and was considering shutting off power to more than 193,000 others, as the Santa Ana winds whipped wildfires in its service territory.

San Diego Gas & Electric blacked out 73,000 customers on Friday during dry, windy conditions. It had restored power to most by Monday but said more than 50,000 customers remained at risk for PSPS.

During the CPUC’s discussion of PG&E’s rate case, commissioners said climate change was pushing fire season later in the year and affecting greater numbers of residents.

“We are in the midst of customers facing shutoffs now because these … dry winds are continuing into December, beyond what has been our usual fire season,” Commissioner Genevieve Shiroma said.